A typical wellhead is often comprised of a casing head or a casing bowl which engages or is otherwise mounted to a casing string contained within a wellbore of a well at the surface. A tubing head or tubing bowl is mounted upon the upper surface of the casing head and provides a support mechanism for a tubing hanger. The tubing hanger is connected to or engages the upper end of the tubing string which is contained within the wellbore. Thus, the tubing hanger and the tubing string connected thereto are supported at the surface of the well by the tubing head. Alternately, the wellhead may not include a casing head. In this case, the tubing head is mounted directly to the casing string at the surface of the well. A reciprocating rod or tube or a rotating rod or tube is then run through the tubing string for production of the well.
A typical wellhead may also further include a tubing rotator. Tubing rotators are used in the industry to suspend and rotate the tubing string within the wellbore. By rotating the tubing string, typical wear occurring within the internal surface of the tubing string by the reciprocating or rotating rod string is distributed over the entire internal surface. As a result, the tubing rotator may prolong the life of the tubing string. Further, the constant movement of the tubing string relative to the rod string may inhibit or reduce buildup of wax and other materials within the tubing string.
Conventional tubing heads are not typically able to be retrofitted to accommodate the necessary structure of a tubing rotator, including the drive system for causing the rotation of the tubing string. Thus, the tubing head may require replacement in the event the operator of the well chooses to commence the use of a rotator subsequent to the initial completion of the well and the wellhead. Further, when a conventional tubing rotator is used in combination with a conventional tubing head, the rotator is typically mounted on top of the tubing head. This arrangement may increase the overall height of the wellhead and may result in the instability of the wellhead by weakening its overall structure.
As well, in order to service the well, the tubing hanger and the connected tubing string must typically be removed from the well. However, any disturbance of the tubing string during servicing may lead to a blowout. To avoid this risk in a conventional well without a tubing rotator, the portion of the wellhead above the tubing head is typically removed and a blowout preventer is mounted to the tubing head. The tubing hanger with the attached tubing string are then removed through the blowout preventer.
Where the wellhead includes a tubing rotator, the structure of the rotator tends to interfere with the installation of the blowout preventer. Thus, in order to service the well, the rotator, or at least a portion of it, must typically be removed from the tubing head. Removal of all or a portion of the rotator may require or result in disturbance of the tubing string, which may lead to a blowout.
Further, when a rotator is in use in the wellhead, the tubing hanger is typically comprised of a swivel dognut assembly. The swivel dognut assembly is comprised of a rotatable mandrel, which is connected to and suspends the tubing string within the wellbore, and a drive system for rotating the mandrel which results in the rotation of the tubing string. The drive system is conventionally comprised of a system of gears which engages the mandrel either directly or indirectly to cause it to rotate. In order to remove these conventional rotators and tubing hangers for servicing of the well, the gear system must first be removed from the rotator such that the mandrel is no longer directly or indirectly engaged thereby. Where the gear system is not so removed, due to an error or oversight, the rotator and the wellhead may be seriously damaged resulting in the costly replacement of equipment, a loss of production during replacement of the equipment and a potential for the blowout of the well.
As well, in order to service the well, a pup joint or servicing tool is typically threaded into the upper end of the inner rotatable mandrel of the swivel tubing hanger. However, upon the removal of the drive system for servicing of the well, the inner mandrel is typically able to freely rotate within the outer supporting structure of the tubing hanger. As a result, connection of the servicing tool may be problematic due to the difficulties encountered in obtaining and ensuring a secure connection between the servicing tool and the inner mandrel of the tubing hanger. This problem is typically addressed by the insertion of a key between the inner mandrel and the outer supporting structure of the tubing hanger during servicing of the well in order to inhibit the rotation of the inner mandrel.
There is therefore a need in the industry for a tubing head capable of accommodating the functional structure or elements of a tubing rotator therein such that the tubing head may be retrofit and converted from its use as a conventional tubing head into its use as a combined tubing head and rotator. Further, there is a need for an apparatus which combines the functional elements of a tubing head and a tubing rotator in a single, integral unit.
As well, there is a need for such a tubing head and apparatus that are relatively compact and that will facilitate the servicing of the well. More particularly, there is a need for such a tubing head and apparatus that permit the removal of the tubing string from the well therethrough without first requiring the removal of all or a portion of the tubing head or apparatus, including the drive system of the tubing rotator. Further, there is a need for such a tubing head and apparatus which permits the removal of the tubing string through a service blowout preventer mounted thereon without first moving the tubing string connected to the tubing rotator. Finally, there is a need for such an apparatus that facilitates the connection of a servicing tool to the components of the tubing rotator during the servicing of the well.